Neutron method for determining residual oil-phase fluid concentration

ABSTRACT

A method for determining the concentration of oil-phase fluid in an earth formation containing indigenous oil-phase fluid and aqueous liquid. A zone in the formation is irradiated with neutrons when the zone is filled with indigenous oil-phase and aqueous liquid. The thermal neutron capture rate response of the zone is measured with respect to the first irradiation. Substantially all indigenous oil-phase is removed from the zone and the zone is filled with only an aqueous liquid substantially equivalent in compositions to the indigeneous aqueous liquid. The zone is irradiated with neutrons a second time and the thermal neutron capture rate response of the zone is measured with respect to the second irradiation.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to well testing; and more particularly, to amethod for determining the concentration of oil-phase fluid in an earthformation.

2. Description of the Prior Art

The importance of determining residual oil in place by means ofsubsurface logging techniques has been recognized for some time. At thepresent, new oil fields are becoming more difficult to discover and moreattention is being given to secondary and tertiary methods of oilrecovery in oil fields. In uncased intervals of a well extending into anoil formation, the oil content can be determined from resistivity logsif the resistivity of a salt-containing formation water within thesurrounding formation is known and is of sufficient contrast inresistivity to the oil. It is understood that other parameters such asporosity and lithology must also be known. However, resistivity logscannot distinguish between oil and fresh water, and it is impossible toobtain resistivity logs in cased wells. Most of oil fields that arebeing considered for secondary and tertiary recovery have only casedwells, since the field has already been produced by primary methods. Thecost of drilling new wells for the sole purpose of running logs inuncased boreholes would in all probability render further recoveryprocesses uneconomical.

The term "indigenous formation fluid" refers to the fluid insubterranean porous rock at the time investigation of a formation isinitiated. In a virgin formation, it is a natural mixture of water-phaseand oil-phase fluid or the presence of a water-phase fluid and anoil-phase fluid. In a formation that has been waterflooded, it is thefluids remaining in the formation at the end of the flooding operation.The oil-phase fluid may be oil, gas, or a mixture of oil and gas.

Conventional formation evaluation techniques are subject to largeuncertainties in region of high water saturation. At 25 percent residualgas or oil saturation, the minimum probable error is about ±8 saturationpercent, and at 10 percent residual saturation the probable error isabout ±10 saturation percent.

Evaluations of gas-bearing intervals in open, or uncased, boreholes aresubject to additional uncertainties due to gas solubility in filtratewater flowing into a water-receptive formation from a borehole. Thedecrease in residual gas saturation is proportional to filtration lossessince, for most sandstones, the filtrate becomes gas saturated quitequickly. As an example of the magnitude of these effects, only 7 porevolumes of gas-free water is required to reduce residual gas by 10saturation percent for assumed reservoir conditions of 3,000 p.s.i. and160°F. (dry gas). Under these conditions, the short spaced resistivityand porosity devices would be affected to some degree even if low waterloss muds are used. Pressure coring, used successively in residual oilapplications, is subject to error due to gas solubility effects duringfiltrate flushing.

In copending application to Richardson et al., Ser. No. 633,963 filedApr. 26, 1967, a method for determining residual oil in a formation thathas been reduced to residual oil by water drive or waterflooding isdisclosed. This method measures the thermal neutron decay first with theformation water and then with water having a materially differentcapture cross section substituted for the formation water at leastwithin the radius of investigation of the logging tools. However, asdiscussed hereinabove, such a technique can be unsuitable for residualgas saturation determination because of the requirement for injection oflarge quantities of water. Due to problems associated with thesolubility of natural gas, it would appear that a cased hole techniquein order to determine residual gas saturation accurately is desirable.Also, the technique disclosed in the copending Richardson et al.application requires an independent measure of porosity and is not asaccurate as desired.

SUMMARY OF THE INVENTION

It is an object of this invention to provide an improved method foraccurately determining the concentration of indigenous oil-phase fluidin an earth formation.

It is a further object of this invention to provide a method foraccurately determining the concentration of indigenous oil-phase fluidin an earth formation using the connate water originally present in theformation.

It is a still further object of this invention to provide a method foraccurately determining the concentration of indigenous oil-phase fluidin an earth formation without the necessity of making independentporosity measurements.

These objects are carried out by irradiating a zone in the formationwith neutrons when the zone is filled with indigenous oil-phase fluidand aqueous liquid. The thermal neutron capture rate response of thezone is measured with respect to the first irradiation and a supply ofthe indigenous aqueous liquid within the zone is preferably producedtherefrom. Substantially all indigenous oil-phase fluid is removed fromthe zone and the zone is filled with only indigenous aqueous liquid or aliquid having a neutron capture cross section substantially equivalentto that of the indigenous aqueous liquid. The zone is irradiated withneutrons a second time and the thermal neutron capture rate response ofthe zone is measured with respect to the second irradiation. Thequantity of indigenous oil-phase fluid saturation times porosity isdetermined from the difference between the measured first and secondresponses.

BRIEF DESCRIPTION OF THE DRAWING

The drawing is an elevation view of a borehole illustrating the methodof this invention.

DESCRIPTION OF THE PREFERRED EMBODIMENT

The theory, equipment and techniques utilized in the present inventionare generally similar to those utilized in the copending application toRichardson with the exception of the changes that are made in the fluidsin the measuring zone between the measurements of the neutron capturerates. Further, where applicable, the discussions in the aforementionedRichardson application pertaining to the carrying out of his inventionare incorporated herein by reference.

It can be seen from the discussion in the copending application toRichardson et al., in pulsed neutron capture (PNC) logging the totalcapture cross section, ΣT, of an interval is comprised of contributionsfrom the rock matrix, Σ_(R), and contained fluids, Σ_(W) and Σ_(hc).This was expressed in the copending application of Richardson as

    ΣT.sub.1 =Σ.sub.R (1-Φ)+Σ.sub.W.sbsb.1 SWΦ+Σ.sub.hc (1-S.sub.W)Φ                   (1)

where

ΣT₁ =total capture cross section for the first measurement,

Σ_(R) =capture cross section of the formation rock,

Φ=porosity of the formation expressed as a fraction,

Σ_(W).sbsb.1 =capture cross section of the water contained in theformation for the first measurement,

S_(w) =fraction of the pore volume containing water, and

Σ_(hc) =capture cross section of the hydrocarbon. However, as Richardsonet al. pointed out, values for Σ_(R) and Σ_(hc) are not required ifthere are two values of Σ_(W) satisfying equation (1) and if the changein Σ_(W) brings about no change in hydrocarbon saturation. The lattercondition is not practicable where a free gas phase is present.

However, inasmuch as natural gas is soluble to some extent in water, andsince PNC logging tools are shallow investigating device, it may befeasible to remove gas saturation from a short homogeneous interval byflushing it thoroughly with formation of water. It has been found thatapproximately 21 pore volumes of water should be sufficient to remove aresidual gas saturation (dry) of 30 percent under reservoir conditionsof 3,000 p.s.i., 160°F. Removal of gas up to 12 inches from the sandface would be adequate in view of the shallow investigatingcharacteristics of PNC logging tools. A large excess of injected watermay be used in order to account for permeability variations, etc. Asdiscussed hereinabove, saturation of injected water by gas takes placeso rapidly that the process is, as a practical matter, rate insensitive.If it is found that gas removal is not highly efficient using water, aliquid hydrocarbon absorber, such as acetone, may be used. The absorbershould be miscible with formation water which would follow in turn.

The expression for total capture cross section after removal of residualgas by one means or another and complete saturation of the pore spacewith formation water is:

    Σ.sub.T.sbsb.2 =Σ.sub.R (1-Φ)+Σ.sub.W Φ(2)

where

Σ_(T).sbsb.2 =total capture cross section at the second measurement.

Rewriting equation (1) in terms of gas saturation and combining with(2), we have

    Σ.sub.T.sbsb.1 =Σ.sub.R (1-Φ)+Σ.sub.W.sbsb.1 (1-S.sub.GR)Φ+Σ.sub.G S.sub.GR Φ ##EQU1## where S.sub.GR =fraction of the pore volume containing gas and

ΣG=capture cross section of the gas contained in the formation.

The application of equation (3) will necessarily be in cased wells whereporosity data may not be available. Further, accurate porosity data areessential since uncertainties in this parameter have been found toconstitute a major source of error. A porosity determination may be madeutilizing pulsed neutron capture log response by performing a seconddisplacement with, say, high-salinity water to change the value of Σ_(W)in (2):

    Σ.sub.T.sbsb.3 =Σ.sub.R (1-Φ)+Σ.sub.W.sbsb.2 Φ(4)

where

Σ_(T).sbsb.3 =total capture cross section for the third measurement(i.e., after injection of high-salinity water) and

Σ_(W).sbsb.2 =capture cross section of the saline-treated watercontained in the formation at the third measurement.

Combining (2) and (4) and solving for Φ: ##EQU2##

Substituting in (3) gives: ##EQU3## which requires three loggingmeasurements and a knowledge of ΣG and ΣW for two waters.

The foregoing calculations may also be used to determine residual oil.The major potential for residual oil determination lies in casedintervals of old wells where good porosity data is not available. Thesequence of operations outlined hereinabove may be carried out in a zonecontaining residual oil if the trapped oil were to be miscibly displacedby injecting a lug of mutual solvent and driving it with formationwater. Alternatively, a preferentially oil-soluble solvent slug may beinjected followed by a preferentially water-soluble solvent slug. Smallamounts of such material are sufficient to displace the residual oilbeyond the depth of investigation of the pulsed neutron capture loggingprocedure disclosed by Richardson et al. and permit the determination ofresidual oil saturations without independent porosity control.Additional passes may be taken so as to achieve as low a probableuncertainty of saturation percent as possible. The procedure of thisapplication for determining residual oil saturation permits thedetermination of the porosity utilizing the method disclosed byRichardson.

From the foregoing, it can be seen that the present invention may beused in conjunction with the method disclosed in the copendingapplication to Richardson et al. in order to measure porosity,rock-capture cross section and other properties of the formation beinginvestigated.

A further feature of the present invention significantly improves theaccuracy available to a residual oil determination. Thus, referring nowto the drawing, there is shown a well bore hole 11 that penetrates anonproducing formation 10 and a producing formation 12. The producingformation 12, the earth formation zone to be investigated, is assumed tobe a uniform formation. However, the method of this invention will alsowork with nonuniform formations. In the case of nonuniform formations,errors may be introduced due to inability to assume a constant porosityfor the formation. The well borehole 11 is assumed to be cased with acasing 14 having a series of perforations 16 adjacent the producingformation 12, although the invention will work equally well in uncasedholes. Such casings are usually surrounded by a cement sheath (notshown) and perforations 16 are extended through the cement sheath. Oneor a few perforations can be used as long as a zone around the boreholecan be substantially uniformly swept by fluid injected through theperforations. All the production tubing, packers, and other equipmentare assumed to be removed from the zone being tested within wellborehole 11. Further in respect to measurements of residual oilsaturation, it is assumed that the well borehole 11 has been produceduntil its oil content is at least as low as a waterflood residual, e.g.,by a natural water drive or a secondary recovery process such aswaterflooding or other type of flood. In some formations, especiallythose that were produced by a gas drive, it may be necessary to floodthe formation with an aqueous liquid before the first measurement inorder to displace gas away from the zone being investigated.

The first step in the method of this invention is to obtain a thermalneutron decay measurement with the oil content being that of theindigenous formation fluid, rather than necessarily being at least aslow as waterflood residual as disclosed in the copending application ofRichardson et al. In the Richardson et al. procedure, those cases wherethe formation has not been reduced to the residual oil level, it isnecessary to inject water into the formation to insure that theformation is reduced to the residual oil level. Of course, it is onlynecessary to inject sufficient water to exceed the radius ofinvestigation of the logging tool. For example, a salt water containingapproximately 20,000 p.p.m. of NaCl and having a cross section ofapproximately 2.9×10⁻ ² cm. ⁻ ¹ could be injected into the formation inthe amount of 1 bbl. per foot of zone to be investigated around aborehole having a diameter of 61/4 inch.

The thermal neutron decay measurements may be obtained by running one ofthe commercially available tools in the well and recording the countingrates indicated as N₁ and N₂. The operation of such tools can be moreeasily understood by referring to FIG. 2 of Richardson et al. showingthe decay curve for thermal neutrons in a borehole and surroundingformations. The pulse 30 represents the pulse of fast neutrons generatedby the neutron source in the tool. This pulse may have a length of about30 microseconds. Following the initial pulse, the neutron intensity isallowed to decay before the start of the first counting interval. Thenormal delay is approximately 400 microseconds. The first countinginterval t₁ may be approximately 200 microseconds long and after a delayof an additional 100 microseconds, the second 200-microsecond countinginterval t₂ is started. The curve 32 represents the approximateexponential decay of the thermal neutron intensity while the intervals36 and 38 represent the two counting intervals. The background level ofradioactivity in the borehole is represented by the horizontal line 34.From an inspection of this curve, it is readily appreciated that thebackground level must be known within reasonable accuracy in order forthe two counting intervals 36 and 38 to be meaningful. Such tools areusually moved along the zone being inspected so that they indicate thevariation with depth of the counting rate during each of the countingintervals.

During the logging of a borehole it is desirable to determine thebackground radioactivity in the borehole. The present invention mayutilize various methods for determining background level. One methodconsists of moving the logging tool, preferably by pulling it up thewell borehole 11 towards a selected depth. Upon reaching the selecteddepth, the tool is stopped and, simultaneously, the neutron source isturned off. The induced radioactivity is recorded during the following40 seconds, and the recorded curve is extrapolated to the time at whichthe source was turned off. A plurality of runs are made in this manner,at least 10 being desirable to reduce the statistical error. This thusprovides an accurate measurement of the background level of theformation surrounding the borehole 11. This background level isprimarily the decay of the nitrogen-16.

Another method for determining the background radioactivity is to injecta saturated boric acid water solution into the zone of earth formationto be investigated. Boric acid has a high capture cross section and thuswill absorb essentially all the thermal neutrons before the firstmeasurement is made by a logging tool having a delay of at least about400 microseconds preceding the measurement. While the thermal neutronsare absorbed, the induced nitrogen-16 radioactivity will not beaffected, since it is produced by a fast neutron reaction. Thus, theresulting measurement will be almost essentially the background level ofthe formation. Again it would be desirable to make repeated runs toobtain a sufficiently high number of counts to determine the backgroundlevel of the formation with accuracy.

The first PNC log is run into reservoir 12 within the borehole 11 withindigenous oil and formation water contained in the reservoir 12 nearthe borehole. The thermal neutron capture rate response is measured asdisclosed in the copending application to Richardson et al. Preferably,a supply of the indigenous oil and aqueous liquid within reservoir 12 isproduced therefrom. By conventional chemical flooding techniques withborehole 11 being used as an injection well, all the residual oil isremoved from the formation within the radius of investigation of the PNClog. This " cleaned" formation is then resaturated with originalformation water or a liquid of substantially the same concentration offormation salts.

Next, a second PNC log is run into the borehole with only formationwater contained in the reservoir near the borehole and the thermalneutron capture rate response is measured a second time.

The foregoing may be accomplished by withdrawing the logging tools fromthe borehole 11, or disposing it so that fluid may be injected past it,and a packer 20 is set immediately above the formation 12. A suitabletubing string 22 is run through the packer 20 so as to inject thepreviously separated indigenous liquid into formation 12. Tubing string22 may also be used to remove the oil and aqueous liquid from theformation 12.

After the above data is obtained, the simultaneous equations may besolved either manually or by the use of a computer as illustrated inFIG. 3 of the copending application to Richardson et al. whichdiscussion is also incorporated herein by reference.

Alternatively to determining the porosity as disclosed by Richardson,the two PNC logs, i.e. the logs taken before and after removal of theresidual oil, give equations (1) and (2), discussed hereinabove, for thetotal formation capture cross section measured by logs 1 and 2,respectively.

The difference of equations (1) and (2) is independent of Σ_(LR) (whereΣ_(LR) =capture cross section of matrix), i.e.:

    Σ.sub.T.sbsb.1 -Σ.sub.T.sbsb.2 =Σ.sub.W.sbsb.1 -Σ.sub.hc (1-S.sub.W)Φ=(ΣW.sub.1 -Σ.sub.hc)S.sub.OR Φ

or ##EQU4## where Σ_(W).sbsb.1 =capture cross section of water information during log No. 1 and

S_(or) =fractional residual oil saturation.

Tests have shown that the uncertainty in residual oil determinationusing the chemical flood technique of this invention is less than onesaturation percent. Thus, the error reduction provided by the presentinvention may be materially greater than the method of Richardson et al.in respect to oils which contain some gas or in respect to subterraneanporous rocks in which the oil-phase fluid is a gas.

Comparing both the method of this invention and the two-water floodtechnique disclosed by Ricardson et al., the Richardson et al. techniquemeasures water saturation directly while the chemical flood technique ofthis invention measures oil saturation directly. This being the case,the two-water flood technique requires an independent measure ofporosity in addition to the PNC log measurements, whereas the chemicalflood technique requires only the NLL measurements for an estimate ofoil contained by unit reservoir bulk volume. Thus, the chemical floodtechnique of this invention leads to more certain estimates ofoil-in-place since fewer measurements are required. The presenttechnique provides a means for increasing the accuracy of themeasurements of residual oil. In the following example, it can be seenthat, where the oil-phase fluid is free of gas, the uncertainty in anoil-in-place determination is reduced to two thirds of that obtained bythe procedure disclosed in the copending application to Richardson.

EXAMPLE 1

The following is an example comparing the relative accuracies of the twosaturation measuring techniques, that is, the two-water flood techniqueof Richardson et al. and the chemical flood technique of this invention.A hypothetical oil reservoir having the following properties is assumed.

    Area(A)           2,000 acres ± 100 acres                                  Oil-Sand Thickness (h)                                                                          20 feet ± 1 foot                                         Porosity(φ)   0.300 ± 0.01                                             Residual Oil Saturation                                                                         0.250                                                       Capture Cross Sections                                                         1. Formation Water                                                                             60.0 × 10.sup.3 cm..sup.1±                             (Σ .sub.w )                                                                           0.600 × 10.sup.3 cm.sup.1                                               (113,000 mg./l NaCl)                                         2. Injection Water                                                                             100 × 10.sup..sup.-3 cm..sup.1±                        (Σ.sub.w )                                                                            1.00 × 10.sup.3 cm..sup.1                                               (229,000 mg./l NaCl)                                         3. Hydrocarbons (Σ.sub.hc)                                                               19.0 × 10.sup.3 cm..sup.1                                               0.570 × 10.sup.3 cm..sup.1                        

Substituting in both the equations presented in the copending Richardsonet al. application relating to the two-water flood technique and in theequations presented in this application relating to the chemical floodtechnique, taking into consideration individual error contributions andtotal error or uncertainty in oil-in-place for both techniques, we findthat the best estimate of oil-in-place is 23.3×10⁶ bbl. with anuncertainty of ±2.94×10⁶ bbl. when measuring residual oil by thetwo-water flood technique as compared to an uncertainty of ±2.01×10⁶bbl. using the chemical flood approach. For the conditions assumed, thechemical flood technique appears to be a more accurate method.

EXAMPLE II

The following is an example of a proposed use of the technique of thisinvention in a new well to be drilled in the Good Hope field inLouisiana.

Estimated data expected to apply to the section of interest in the newwell include: Temperature ≈ 190°F., porosity ≈ 32 percent, permeability≈ 2,800 md., bottom hole pressure ≈ 3,800 p.s.i., depth 8,300 ft.,formation water total dissolved solids ≈ 116,000 p.p.m., formation watermultivalent ion concentration ≈ 3,500 p.p.m., residual oil saturation ≈15 percent, and thickness of interval to be flooded by chemical ≈ 15 ft.To insure that residual oil is moved outside the zone of investigationof the logging tool, it is desired to flood out a minimum radius of twofeet from the borehole.

Composition of the recommended chemical system as indicated by emulsiontests at field temperature with field crude is as follows:Sulfonate--0.045 meq. g., NaCl--20,000 p.p.m., and sodiumtripolyphosphate--5,000 p.p.m. Viscosity of the solution at 190°F. andat a shear rate of 230 sec⁻ ¹ is 0.6 cp. Oil viscosity is estimated tobe 0.5 cp. at reservoir temperature. Compatibility of this sulfonatesystem with formation water is not complete; dilution with 25 percent byvolume of formation water will cause "salting out" and flocculation ofsulfonate. It will, therefore, be necessary to both precede and followthe sulfonate injection with the injection of water containing 20,000p.p.m. of sodium chloride.

It is expected that the zone of interest for the test will be overlainby a zone having high oil saturation and underlain by a zone of zero oilsaturation. No significant change in rock properties in these threelayers is expected and vertical communication must be assumed. Sulfonateinjected into the intermediate saturation zone of interest will tend tomove down into the high water saturation zone. Consideration should begiven to this potential "sweep" problem in the design of the perforatingpattern, in the determination of injection rates to be used in the test,and in the determination of total volume of sulfonate to be injected. Ifthis under running problem did not exist, it would be desirable toinject sulfonate in a volume equivalent to two pore volumes of the zoneto be swept. To sweep a radial zone having a diameter of 4 feet wouldrequire about 3 bbl. per foot of section or a total of 45 barrels forthe expected 15 ft. section. To provide adequate safety factor, it isrecommended that at least 100 bbl. of sulfonate be injected. Thissolution should be preceded and followed by 25 barrels of watercontaining 20,000 p.p.m. NaCl.

To provide a sulfonate solution having the desired physical and chemicalproperties it is necessary that proper mixing procedures be followed andthat the temperature of the final solution not be allowed to drop below30°C. Two preliminary or "stock" solutions should be prepared first(minimum temperature --5°C.). These "stock" solutions are then mixed inequal volumes to prepare the final solution. Water used in preparationof the solutions should have zero undissolved solids and should haveless than 1,000 p.p.m. total dissolved solids.

Stock solution "A" is prepared by dissolving three drums (1,300 lb.) ofthe aforementioned sulfonate concentrate in 47 barrels of water.Solution "B" is prepared by dissolving 175 lb. of sodiumtripolyphosphate and 700 lb. of salt in 49 barrels of water. Thesesolutions can be prepared as long in advance of use as is desired. Afterthey are mixed in equal volumes, sulfonate will be precipitated if thesolution is allowed to stand for several hours at temperatures below30°C. A satisfactory handling procedure would be to pump simultaneouslyand at the same volumetric rate from two stock tanks into the well.Adequate mixing and temperature control would be achieved in the linesand tubing before the solution reached the formation face.

We claim as our invention:
 1. In a method for determining theconcentration of indigenous oil-phase fluid in an earth formationcontaining indigenous oil-phase fluid and aqueous liquid, the processcomprising the steps of:irradiating with a pulse of neutrons a zonewithin said formation when said zone is filled with said indigenousoil-phase fluid and aqueous liquid; measuring the thermal neutroncapture rate response of the zone to said irradiation; removingsubstantially all indigenous oil-phase fluid from the zone; filling saidzone with an aqueous liquid substantially equivalent in composition tosaid indigenous aqueous liquid; irradiating the zone with a pulse ofneutrons a second time; measuring the thermal neutron capture rateresponse of the zone to said second irradiation; and determining thequantity of the indigenous oil-phase fluid saturation times porosityfrom the difference between said measured first and said secondresponses.
 2. The method of claim 1 including the step of flooding saidearth formation with an aqueous liquid prior to first irradiating saidzone so as to displace any gas present in said formation away from thezone being irradiated.
 3. The method of claim 1 including the step ofproducing said well until its oil content is at least as low aswaterflood residual prior to irradiating said zone a first time.
 4. Themethod of claim 3 wherein the step of producing said well includes thestep of injecting sufficient water into said well so as to reduce theresidual oil level.
 5. The method of claim 4 wherein the steps ofinjecting sufficient water includes injecting salt water sufficient toexceed the radius of investigation of the zone.
 6. The method of claim 1including the step of producing therefrom a supply of the indigenousoil-phase fluid and aqueous liquid within said zone; andseparating saidaqueous liquid from said indigenous oil-phase fluid; and employing saidseparated aqueous liquid in the step of filling said zone with anaqueous liquid. .Iadd.
 7. A method of measuring water saturation in asubsurface zone penetrated by a well bore which comprises the steps of:a. running a logging instrument in said well bore to measure the watersaturation of the rock in said zone adjacent said well bore, b.injecting a driving fluid through said well bore into said zone todisplace oil out of the rock immediately surrounding the well bore, saiddriving fluid easily driven through the rock by a second driving fluidhaving the same logging characteristics as the water in the rock at thetime of Step (a), c. injecting said second driving fluid through saidwell bore into said zone to drive said first driving fluid from the zoneimmediately adjacent the well bore, and d. after Step (c), repeatingStep (a). .Iaddend. .Iadd.
 8. A method as defined in claim 7 in whichStep (a) is the running of a thermal neutron decay time log..Iaddend..Iadd.
 9. A method as defined in claim 7 in which said firstdriving fluid is a micellar solution having mutual solubility in oil andin water. .Iaddend..Iadd.
 10. A method as defined in claim 9 whichcomprises the step of injecting a water slug before Step (c)..Iaddend..Iadd.
 11. A method as defined in claim 10 which includes thestep of injecting water after Step (c). .Iaddend..Iadd.
 12. A method asdefined in claim 7 in which before Step (a) the well is conditioned toproduce as near as possible the same fluid saturation adjacent the boreas that present in the rock formation remote from the well bore..Iaddend..Iadd.
 13. A method as defined in claim 7 when used in a zonehaving gas saturation, the method including the step of running logs todetermine the gas saturation, such logs to be run after Step (a) andbefore Step (b). .Iaddend..Iadd.
 14. A method of measuring watersaturation in a subsurface zone penetrated by a well bore whichcomprises the steps of:
 1. measuring the water saturation of the rock insaid zone adjacent said well bore,
 2. thereafter reducing to zero theoil saturation of the rock immediately surrounding the well bore, 3.filling the pore space of the rock adjacent the well bore with a fluidhaving the same logging characteristics as the water in the rock at thetime of Step (1),
 4. after Step 3 again measuring the water saturationof the rock in said zone adjacent said well bore. .Iaddend. .Iadd.
 15. Amethod for determining the residual oil in an oil bearing formationpenetrated by the borehole of a well comprising the steps of: a. loggingsaid formation to obtain logging data measurements of the relativequantities of residual oil and formation water present in the formation;b. injecting into said formation, through said borehole, a sufficientamount of an oil miscible solution, to displace substantially all of theresidual oil in said formation surrounding said borehole to a distanceexceeding the radius of investigation of the logging means providing thelogging data; c. injecting into said formation through said borehole asufficient amount of water to displace substantially all of said oilmiscible solution and cause said formation being tested to besubstantially 100% water saturated; and d. logging for a second timesaid formation to obtain logging data measurements; and e. comparing thelogging data measurements of said second log with the logging datameasurements of said first log to determine the amount of residual oilin said formation. .Iaddend.